U.S. patent application number 10/440337 was filed with the patent office on 2004-11-18 for method for stimulating hydrocarbon production and reducing the production of water from a subterranean formation.
Invention is credited to Dalrymple, Eldon D., Eoff, Larry S., Reddy, B. Raghava.
Application Number | 20040229756 10/440337 |
Document ID | / |
Family ID | 33417984 |
Filed Date | 2004-11-18 |
United States Patent
Application |
20040229756 |
Kind Code |
A1 |
Eoff, Larry S. ; et
al. |
November 18, 2004 |
Method for stimulating hydrocarbon production and reducing the
production of water from a subterranean formation
Abstract
Improved methods and solutions for treating water and
hydrocarbon producing subterranean formations to reduce the water
permeability thereof are provided. The improved aqueous solutions
comprise a hydrophilic reactive polymer, a hydrophobic compound
capable of reacting with the polymer in situ and a surfactant. The
methods basically comprise preparing and introducing into the
formation the aqueous solution followed by shutting in the
formation in order to permit reaction of the polymer and the
hydrophobic compound. The reaction product attaches to adsorption
sites on surfaces within the porosity of the formation and reduces
the water permeability thereof without substantially reducing the
hydrocarbon permeability thereof. Additionally, the current
invention provides a pre-reacted hydrophobically modified relative
permeability modifier and formation stimulation/re-stimulation
methods for using the same.
Inventors: |
Eoff, Larry S.; (Duncan,
OK) ; Reddy, B. Raghava; (Duncan, OK) ;
Dalrymple, Eldon D.; (Duncan, OK) |
Correspondence
Address: |
Robert A. Kent
Halliburton Energy Services
2600 South 2nd Street
Duncan
OK
73536
US
|
Family ID: |
33417984 |
Appl. No.: |
10/440337 |
Filed: |
May 16, 2003 |
Current U.S.
Class: |
507/219 |
Current CPC
Class: |
C09K 8/68 20130101; C09K
8/10 20130101 |
Class at
Publication: |
507/219 |
International
Class: |
E21B 043/00 |
Claims
We claim:
1. An aqueous well treatment solution comprising: an aqueous
solution of a hydrophilic reactive polymer, a hydrophobic compound
capable of reacting with the hydrophilic reactive polymer and a
sufficient quantity of a surfactant capable of promoting the
dissolution of the hydrophobic compound in the aqueous
solution.
2. The well treatment solution of claim 1, wherein the hydrophilic
reactive polymer is a homo-, co- or ter-polymer having at least one
reactive amino group.
3. The well treatment solution of claim 1, wherein the hydrophilic
reactive polymer is selected from the group consisting of
polyethyleneimine, polyvinylamine, poly(vinylamine/vinyl alcohol),
chitosan, polylysine and alkyl acrylate polymers.
4. The well treatment solution of claim 3 wherein the alkyl
acrylate polymer comprises a polymer containing at least one
monomer selected from the group consisting of dimethylaminoethyl
methacrylate and dimethylaminopropyl methacrylamide.
5. The well treatment solution of claim 1, wherein the hydrophilic
reactive polymer is poly-dimethylaminoethylmethacrylate.
6. The well treatment solution of claim 1, wherein the hydrophobic
compound is selected from the group consisting of alkyl halides
wherein the alkyl chain portion has from about 6 to about 30
carbons.
7. The well treatment solution of claim 1, wherein the hydrophobic
compound is cetyl bromide.
8. The well treatment solution of claim 1, wherein the surfactant
is selected from the group of anionic, cationic, amphoteric or
neutral surfactants.
9. The well treatment solution of claim 1, wherein the surfactant
is selected from the group consisting of alkyl ammonium
surfactants, betaines, alkyl ether sulfates, alkyl ether
sulfonates, and ethoxylated alcohols.
10. The well treatment solution of claim 1, wherein the hydrophilic
reactive polymer comprises from about 0.1 to about 2.0 percent by
weight of the aqueous solution.
11. The well treatment solution of claim 1, wherein the hydrophilic
reactive polymer comprises from about 0.2 to about 1.5 percent by
weight of the aqueous solution.
12. The well treatment solution of claim 1, wherein the hydrophobic
compound comprises from about 0.01 to about 1.0 percent by weight
of the aqueous solution.
13. The well treatment solution of claim 1, wherein the hydrophobic
compound comprises from about 0.02 to about 0.5 percent by weight
of the aqueous solution.
14. The well treatment solution of claim 1, wherein the surfactant
comprises from about 0.1 to about 1.0 percent by weight of the
aqueous solution.
15. The well treatment solution of claim 1, further comprising a pH
adjusting agent selected from the group consisting of buffers,
alkali metal hydroxides, alkali metal carbonates, alkali and metal
phosphates.
16. The well treatment solution of claim 1, further comprising a
hydrated galactomannan gelling agent selected from the group
consisting of guar, hydroxyethylguar, hydroxypropylguar,
carboxymethylguar, carboxymethylhydroxyethylguar and
carboxymethylhydroxypropylguar.
17. The well treatment solution of claim 15, wherein the hydrated
galactomannan gelling agent comprises from about 0.06 to about 0.72
percent by weight of the aqueous solution.
18. An aqueous well treatment solution comprising: an aqueous
solution of a hydrophilic reactive polymer, wherein the polymer is
a homo-, co- or ter-polymer having at least one reactive amino
group, a hydrophobic compound capable of reacting with the
hydrophilic reactive polymer, a pH adjusting agent and a sufficient
quantity of a surfactant capable of promoting the dissolution of
the hydrophobic compound in the aqueous solution.
19. The well treatment solution of claim 18, wherein the
hydrophilic reactive polymer is selected from the group consisting
of polyethyleneimine, polyvinylamine, poly(vinylamine/vinyl
alcohol), chitosan, polylysine and alkyl acrylate polymers.
20. The well treatment solution of claim 19, wherein the alkyl
acrylate polymer comprises a polymer containing at least one
monomer selected from the group consisting of dimethylaminoethyl
methacrylate and dimethylaminopropyl methacrylamide.
21. The well treatment solution of claim 18, wherein the
hydrophilic reactive polymer is
poly-dimethylaminoethylmethacrylate.
22. The well treatment solution of claim 18, wherein the
hydrophobic compound is selected from the group consisting of alkyl
halides wherein the alkyl chain portion has from about 6 to about
30 carbons.
22. The well treatment solution of claim 18, wherein the
hydrophobic compound is cetyl bromide.
23. The well treatment solution of claim 18, wherein the surfactant
is selected from the group consisting of alkyl ammonium
surfactants, betaines, alkyl ether sulfates, alkyl ether
sulfonates, and ethoxylated alcohols.
24. The well treatment solution of claim 18, wherein the
hydrophilic reactive polymer comprises from about 0.1 to about 2.0
percent by weight of the aqueous solution.
25. The well treatment solution of claim 18, wherein the
hydrophilic reactive polymer comprises from about 0.2 to about 1.5
percent by weight of the aqueous solution.
26. The well treatment solution of claim 18, wherein the
hydrophobic compound comprises from about 0.01 to about 1.0 percent
by weight of the aqueous solution.
27. The well treatment solution of claim 18, wherein the
hydrophobic compound comprises from about 0.02 to about 0.5 percent
by weight of the aqueous solution.
28. The well treatment solution of claim 18, wherein the surfactant
comprises from about 0.1 to about 2.0 percent by weight of the
aqueous solution.
29. The well treatment solution of claim 18, wherein the pH
adjusting agent is selected from the group consisting of buffers,
alkali metal hydroxides, alkali metal carbonates, and alkali metal
phosphates.
30. The well treatment solution of claim 18, further comprising a
hydrated galactomannan gelling agent selected from the group
consisting of guar, hydroxyethylguar, hydroxypropylguar,
carboxymethylguar, carboxymethylhydroxyethylguar and
carboxyymethylhydroxypropylguar.
31. The well treatment solution of claim 29, wherein the hydrated
galactomannan gelling agent comprises from about 0.06 to about
0.072 percent by weight of the aqueous well treating solution.
32. An aqueous well treatment solution comprising: an aqueous
solution of a hydrophilic reactive polymer, a hydrophobic compound
capable of reacting with the hydrophilic reactive polymer, a pH
adjusting agent, a hydrated galactomannan gelling agent and a
sufficient quantity of a surfactant capable of promoting the
dissolution of the hydrophobic compound in the aqueous solution;
the hydrophilic reactive polymer is a homo-, co- or terpolymer
having at least one reactive amino group; the hydrophobic compound
is selected from the group consisting of alkyl halides wherein the
alkyl chain portion has from about 6 to about 30 carbons; and the
surfactant is selected from the group consisting of alkyl ammonium
surfactants, betaines, alkyl ether sulfates, alkyl ether
sulfonates, and ethoxylated alcohols.
33. The well treatment solution of claim 32, wherein the
hydrophilic reactive polymer is selected from the group consisting
of polyethyleneimine, polyvinylamine, poly(vinylamine/vinyl
alcohol), chitosan, polylysine and alkyl acrylate polymers.
34. The well treatment solution of claim 33, wherein the alkyl
acrylate polymer comprises a polymer containing at least one
monomer selected from the group consisting of dimethylaminoethyl
methacrylate and dimethylaminopropyl methacrylamide.
35. The well treatment solution of claim 32, wherein the
hydrophobic compound is cetyl bromide.
36. The well treatment solution of claim 32, wherein the
hydrophilic reactive polymer comprises from about 0.1 to about 2.0
percent by weight of the aqueous solution.
37. The well treatment solution of claim 32, wherein the
hydrophilic reactive polymer comprises from about 0.2 to about 1.5
percent by weight of the aqueous solution.
38. The well treatment solution of claim 32, wherein the
hydrophobic compound comprises from about 0.01 to about 1.0 percent
by weight of the aqueous solution.
39. The well treatment solution of claim 32, wherein the
hydrophobic compound comprises from about 0.02 to about 0.5 percent
by weight of the aqueous solution.
40. The well treatment solution of claim 32, wherein the surfactant
comprises from about 0.1 to about 2.0 percent by weight of the
aqueous solution.
41. The well treatment solution of claim 32, wherein the pH
adjusting agent is selected from the group consisting of buffers,
alkali metal hydroxides, alkali metal carbonates, and alkali metal
phosphates.
42. The well treatment solution of claim 32, wherein the hydrated
galactomannan gelling agent is selected from the group consisting
of guar, hydroxyethylguar, hydroxypropylguar, carboxymethylguar,
carboxymethylhydroxyethylguar and
carboxymethylhydroxypropylguar.
43. The well treatment solution of claim 32, wherein the hydrated
galactomannan gelling agent comprises from about 0.06 to about
0.072 percent by weight of the aqueous well treating solution.
44. A method for stimulating or re-stimulating a hydrocarbon
producing formation penetrated by a wellbore comprising the steps
of: forming an aqueous solution comprising a hydrophilic reactive
polymer, a hydrophobic compound capable of reacting with the
hydrophilic reactive polymer, and a sufficient quantity of a
surfactant capable of promoting the dissolution of the hydrophobic
compound in the aqueous solution; adjusting the pH to at least 8;
and pumping the aqueous solution through the wellbore at a rate and
pressure sufficient to fracture the hydrocarbon producing
formation.
45. The method of claim 44, further comprising the step of adding
to the aqueous solution a hydrated galactomannan gelling agent
selected from the group consisting of guar, hydroxyethylguar,
hydroxypropylguar, carboxymethylguar, carboxymethylhydroxyethylguar
and carboxymethylhydroxypropylguar.
46. The method of claim 44, further comprising the step of shutting
in the wellbore for about 1 minute to about 24 hours.
47. The method of claim 44, further comprising the step of pumping
a crosslinked gelled fluid through the wellbore after the aqueous
solution.
48. The method of claim 44, wherein the hydrophilic reactive
polymer is selected from the group consisting of polyethyleneimine,
polyvinylamine, poly(vinylamine/vinyl alcohol), chitosan,
polylysine and alkyl acrylate polymers.
49. The well treatment solution of claim 48, wherein the alkyl
acrylate polymer comprises a polymer containing at least one
monomer selected from the group consisting of dimethylaminoethyl
methacrylate and dimethylaminopropyl methacrylamide.
50. The method of claim 44, wherein the hydrophobic compound is
selected from the group consisting of alkyl halides wherein the
alkyl chain portion has from about 6 to about 30 carbons.
51. The method of claim 44, wherein the surfactant is selected from
the group consisting of alkyl ammonium surfactants, betaines, alkyl
ether sulfates, alkyl ether sulfonates, and ethoxylated
alcohols.
52. The method of claim 44, wherein the hydrophilic reactive
polymer comprises from about 0.1 to about 2.0 percent by weight of
the aqueous solution.
53. The method of claim 44, wherein the hydrophobic compound
comprises from about 0.01 to about 1.0 percent by weight of the
aqueous solution.
54. The method of claim 44, wherein the surfactant comprises from
about 0.1 to about 2.0 percent by weight of the aqueous
solution.
55. The method of claim 44, further comprising the step of pumping
sufficient aqueous solution into the resulting fracture to reduce
formation permeability to water.
56. A method for stimulating or re-stimulating a hydrocarbon
producing formation penetrated by a wellbore comprising the steps
of: forming an aqueous solution comprising a hydrophilic reactive
polymer, wherein the hydrophilic reactive polymer is a homo-, co-
or ter-polymer having at least one reactive amino group, a
hydrophobic compound capable of reacting with the hydrophilic
reactive polymer, and a sufficient quantity of a surfactant capable
of promoting the dissolution of the hydrophobic compound in the
aqueous solution; adjusting the pH to at least 8; pumping the
aqueous solution through the wellbore at a rate and pressure
sufficient to fracture the hydrocarbon producing formation; and
pumping a crosslinked gelled fluid through the wellbore after the
aqueous solution.
57. The method of claim 56, further comprising the step of adding
to the aqueous solution a hydrated galactomannan gelling agent
selected from the group consisting of guar, hydroxyethylguar,
hydroxypropylguar, carboxymethylguar, carboxymethylhydroxyethylguar
and carboxymethylhydroxypropylguar.
58. The method of claim 56, further comprising the step of shutting
in the wellbore for about 1 minute to about 24 hours.
59. The method of claim 56, wherein the hydrophilic reactive
polymer is selected from the group consisting of polyethyleneimine,
polyvinylamine, poly(vinylamine/vinyl alcohol), chitosan,
polylysine and alkyl acrylate polymers.
60. The well treatment solution of claim 59, wherein the alkyl
acrylate polymer comprises a polymer containing at least one
monomer selected from the group consisting of dimethylaminoethyl
methacrylate and dimethylaminopropyl methacrylamide.
61. The method of claim 56, wherein the hydrophobic compound is
selected from the group consisting of alkyl halides wherein the
alkyl chain portion has from about 6 to about 30 carbons.
62. The method of claim 56, wherein the surfactant is selected from
the group consisting of alkyl ammonium surfactants, betaines, alkyl
ether sulfates, alkyl ether sulfonates, and ethoxylated
alcohols.
63. The method of claim 56, wherein the hydrophilic reactive
polymer comprises from about 0.1 to about 2.0 percent by weight of
the aqueous solution.
64. The method of claim 56, wherein the hydrophobic compound
comprises from about 0.01 to about 1.0 percent by weight of the
aqueous solution.
65. The method of claim 56, wherein the surfactant comprises from
about 0.1 to about 2.0 percent by weight of the aqueous
solution.
66. The method of claim 56, further comprising the step of pumping
sufficient aqueous solution into the resulting fracture to reduce
formation permeability to water.
67. An aqueous well treatment solution comprising: a
hydrophobically modified, water soluble relative permeability
modifier wherein the hydrophobically modified, water soluble
relative permeability modifier comprises about 0.05% to about 1.0%
by weight of the aqueous well treatment solution; and a hydrated
galactomannan gelling agent comprising about 0.06% to about 0.72%
by weight of the aqueous solution.
68. The aqueous well treatment fluid of claim 67, wherein the
hydrated galactomannan gelling agent is selected from the group
consisting of guar, hydroxyethylguar, hydroxypropylguar,
carboxymethylguar, carboxymethylhydroxyethylguar and
carboxymethylhydroxypropylguar.
69. The aqueous well treatment fluid of claim 67, wherein the
hydrophobically modified, water soluble relative permeability
modifier comprises a hydrophilic portion selected from the group
consisting of polyethyleneimine, polyvinylamine,
poly(vinylamine/vinyl alcohol), chitosan, polylysine; and a
hydrophobic portion wherein the hydrophobic portion is an alkyl
chain having from about 6 to about 30 carbons.
70. The aqueous well treatment fluid of claim 67, wherein the
hydrophobically modified, water soluble relative permeability
modifier comprises at least one hydrophilic monomer selected from
the group consisting of: acrylamide, 2-acrylamido-2-methyl propane
sulfonic acid, N,N-dimethylacrylamide, vinyl pyrrolidone,
dimethylaminoethyl methacrylate, acrylic acid,
dimethylaminopropylmethacrylamide, trimethylammoniumethyl
methacrylate chloride, methacrylamide hydroxyethyl acrylate; and at
least one monomer selected from the group consisting of: alkyl
acrylates, alkyl methacrylates, alkyl acrylamides alkyl
methacrylamides wherein the alkyl radicals have from about 4 to
about 22 carbon atoms, alkyl dimethylammoniumethyl methacrylate
bromide, alkyl dimethylammoniumethyl methacrylate chloride and
alkyl dimethylammoniumethyl methacrylate iodide wherein the alkyl
radicals have from about 4 to about 22 carbon atoms and alkyl
dimethylammonium-propylme- thacrylamide bromide, alkyl
dimethylammonium propylmethacrylamide chloride and alkyl
dimethylammonium-propylmethacrylamide iodide wherein the alkyl
groups have from about 4 to about 22 carbon atoms.
71. A method for stimulating or re-stimulating hydrocarbon
production from a subterranean formation penetrated by a wellbore
and for reducing the water permeability of the subterranean
formation comprising the steps of: pumping an aqueous well
treatment solution comprising a hydrophobically modified, water
soluble relative permeability modifier through the wellbore at a
rate and pressure sufficient to fracture the formation.
72. The method of claim 71, further comprising the step of gelling
the hydrophobically modified, water soluble relative permeability
modifier by addition of a hydrated galactomannan gelling agent
selected from the group consisting of guar, hydroxyethylguar,
hydroxypropylguar, carboxymethylguar, carboxymethylhydroxyethylguar
and carboxymethylhydroxypropylguar.
73. The method of claim 71, further comprising the step of pumping
a crosslinked gelled fluid into the formation after the
hydrophobically modified, water soluble relative permeability
modifier.
74. The method of claim 71, wherein the hydrophobically modified,
water soluble relative permeability modifier is the reaction
product of a hydrophilic reactive polymer and a hydrophobic
compound.
75. The method of claim 74, wherein the hydrophobic compound is
selected from the group consisting of alkyl halides wherein the
alkyl chain portion has from about 6 to about 30 carbons.
76. The method of claim 71, wherein the hydrophobically modified,
water soluble relative permeability modifier comprises a
hydrophilic portion selected from the group consisting of
polyethyleneimine, polyvinylamine, poly(vinylamine/vinyl alcohol),
chitosan, polylysine and a hydrophobic portion wherein the
hydrophobic portion is an alkyl chain having from about 6 to about
30 carbons.
77. The method of claim 71, further comprising the step of pumping
sufficient aqueous solution into the resulting fracture to reduce
formation permeability to water.
78. The method of claim 71, wherein the hydrophobically modified,
water soluble relative permeability modifier comprises at least one
hydrophilic monomer selected from the group consisting of:
acrylamide, 2-acrylamido-2-methyl propane sulfonic acid,
N,N-dimethylacrylamide, vinyl pyrrolidone, dimethylaminoethyl
methacrylate, acrylic acid, dimethylaminopropylmethacrylamide,
trimethylammoniumethyl methacrylate chloride, methacrylamide
hydroxyethyl acrylate; and at least one monomer selected from the
group consisting of: alkyl acrylates, alkyl methacrylates, alkyl
acrylamides alkyl methacrylamides wherein the alkyl radicals have
from about 4 to about 22 carbon atoms, alkyl dimethylammoniumethyl
methacrylate bromide, alkyl dimethylammoniumethyl methacrylate
chloride and alkyl dimethylammoniumethyl methacrylate iodide
wherein the alkyl radicals have from about 4 to about 22 carbon
atoms and alkyl dimethylammonium-propylmethacrylamide bromide,
alkyl dimethylammonium propylmethacrylamide chloride and alkyl
dimethylammonium-propylmethacrylamide iodide wherein the alkyl
groups have from about 4 to about 22 carbon atoms.
Description
BACKGROUND OF THE INVENTION
[0001] The present invention provides improvements in the
production of hydrocarbons from subterranean formations. More
precisely, the present invention provides improved solutions and
methods for stimulating the production of hydrocarbons while
reducing the production of water from a stimulated subterranean
formation.
[0002] The production of water with hydrocarbons, i.e., oil and/or
gas, from wells constitutes a major problem and expense in the
production of the hydrocarbons. While hydrocarbon producing wells
are usually completed in hydrocarbon producing formations, the
formations frequently contain layers of water or may be located
adjacent to water producing zones. The high mobility of the water
often allows it to flow into the wellbore by way of natural
fractures and/or high permeability streaks present in the
formation. Over the life of such wells, the ratio of water to
hydrocarbons recovered often becomes so high that the cost of
producing the water, separating it from the hydrocarbons and
disposing of it represents a significant economic loss.
[0003] In order to reduce the production of undesired water from
hydrocarbon producing formations, aqueous polymer solutions
containing cross-linking agents have been utilized heretofore. In
the case of naturally fractured formations such aqueous polymer
solutions have been pumped into the hydrocarbon producing
formations so that they enter water zones within and adjacent to
the formations and cross-link therein. The cross-linking of the
polymer solutions forms stiff gels capable of stopping or reducing
the flow of the undesired water. While the use of aqueous polymer
solutions for reducing the production of undesired water has
achieved varying degrees of success, the full blocking gels
produced are not suitable for producing formation treatments unless
the polymer solution can be placed solely in the offending water
producing zone or zones therein. If a polymer solution is allowed
to gel within a hydrocarbon producing zone, the cross-linked
polymer gel formed will reduce or stop the flow of hydrocarbons in
addition to the flow of water. Further, the selected placement of a
polymer solution in a producing formation requires expensive,
time-consuming zonal isolation placement technology. In addition,
even when a polymer solution is properly placed in a water
producing zone, the cross-linked gels formed often do not remain
stable in the zone due to thermal degradation and/or differences in
the adsorption characteristics of the polymer and associated
cross-linker and the like.
[0004] Stimulation processes have long been used in the field of
hydrocarbon production to increase the flow of hydrocarbons to the
well bore. Typically, the stimulation process uses specialized
fluids pumped at sufficient pressure to fracture the formation.
Fracturing the formation increases the surface area available for
fluid to flow to the bore hole. Unfortunately, when a formation
contains high permeability streaks or nearby intervals capable of
producing Water, stimulation frequently leads to the undesired
production of water with the hydrocarbons.
[0005] Recently, chemicals referred to as relative permeability
modifiers have been utilized to decrease the production of water
with hydrocarbons. That is, water permeability modifying chemicals
such as polyacrylamide have been introduced into hydrocarbon and
water producing formations so that the chemicals attach to
adsorption sites on surfaces within the porosity of the formations.
The presence of the chemicals in the formations has the effect of
reducing the flow of water through the formations. The use of water
permeability modifying chemicals in hydrocarbon and water producing
formations to decrease the production of water involves less risk
than other techniques such as blocking the flow of water with
cross-linked polymers, and has the advantage that they do not
require expensive zonal isolation techniques. However, the use of
such hydrophilic water permeability modifying chemicals, e.g.,
polyacrylamides, have heretofore resulted in only small temporary
reductions in water production and/or unacceptable levels of
reduction in hydrocarbon production.
[0006] Thus, improvements are necessary in the methods and
solutions used to reduce water permeability if water and
hydrocarbon producing subterranean formations. Additionally,
improved formation stimulation methods capable of stimulating
production while also reducing the production of water from a
formation are necessary.
SUMMARY OF THE INVENTION
[0007] The current invention provides well treatment solutions
capable of precluding or reducing the production of water from
subterranean formations penetrated by a wellbore. In one
embodiment, the well treatment solution comprises an aqueous well
treatment solution comprising a hydrophilic reactive polymer, a
hydrophobic compound capable of reacting with the hydrophilic
reactive polymer and a sufficient quantity of a surfactant chosen
for its ability to promote dissolution of the hydrophobic compound
in the aqueous solution.
[0008] Additionally, the current invention provides a well
treatment solution for precluding or at least reducing the
production of water from a hydrocarbon producing subterranean
formation. The well treatment solution is an aqueous solution,
comprising a pH adjusting agent, a hydrophilic reactive polymer in
the form of a homo-, co- or ter-polymer having at least one
reactive amino group. Additionally, the solution comprises a
hydrophobic compound capable of reacting in situ during fracture
stimulation with the hydrophilic reactive polymer to form a
hydrophobically modified polymer. Preferred hydrophobic compounds
are alkyl halides having an alkyl chain length of about 6 to about
30 carbons. Typically, the solution further comprises a surfactant
capable of promoting the dissolution of the hydrophobic compound
within the aqueous solution. Suitable surfactants include, but are
not necessarily limited to alkyl ammonium surfactants, betaines,
alkyl ether sulfates, alkyl ether sulfonates, and ethoxylated
alcohols. Optionally, the well treatment solution may be gelled by
the addition of a hydrated galactomannan gelling agent.
[0009] The current invention also provides improved methods for
stimulating or re-stimulating a hydrocarbon producing formation
using an aqueous solution capable of reducing or precluding the
production of water from a subterranean formation. The aqueous
solution is pumped into the wellbore at a rate and pressure
sufficient to fracture the formation.
[0010] The method of the current invention prepares an aqueous
solution comprising a hydrophilic reactive polymer and a
hydrophobic compound capable of reacting with the hydrophilic
reactive polymer to form a hydrophobically modified polymer. In
this embodiment, the reaction preferably occurs in situ and is
facilitated by use of a pH adjusting agent capable of providing a
pH of about 8 or higher to the aqueous solution containing the
reactive polymers. Additionally, the aqueous solution preferably
contains a surfactant selected to promote the dissolution of the
hydrophobic compound within the aqueous solution. The aqueous
solution may be followed with a crosslinked gelled fluid to extend
the fractures into the subterranean formation and transport
proppant into the fractures.
[0011] In an alternative embodiment the current invention provides
an improved well treatment solution comprising a pre-reacted
hydrophobically modified, water soluble relative permeability
modifier (RPM). The well treatment fluid may optionally be in the
form of a gelled fluid containing hydrated galactomannan gelling
agent. Typically, the well treatment solution comprises about 0.05%
to about 1.0% hydrophobically modified RPM by weight and from about
0.06% to about 0.72% gelling agent by weight.
[0012] Additionally, the current invention provides a method for
stimulating or re-stimulating hydrocarbon production from a
subterranean formation while simultaneously treating the formation
to selectively reduce the permeability of the formation to the flow
of water. The method of the current invention pumps a pre-reacted
hydrophobically modified, water soluble RPM as an aqueous solution
into the wellbore at a rate and pressure sufficient to fracture the
formation. If formation conditions dictate the use of a gelled
fluid, then the aqueous solution may be gelled by the addition of a
hydrated galactomannan gelling agent. When stimulating or
re-stimulating the formation, the aqueous solution may be followed
with a crosslinked gelled fluid to extend the created fractures
into the subterranean formation and transport proppant into the
fractures. Use of the pre-reacted hydrophobically modified RPM
eliminates the need for a surfactant in the well treatment solution
and permits operation at a lower pH in the downhole
environment.
DESCRIPTION OF THE PREFERRED EMBODIMENTS
[0013] The solutions and methods of the current invention are
applicable in both newly drilled formations and in formations
requiring re-stimulation. The solutions of the current invention
are particularly useful for formation re-stimulations where
hydrocarbons will be present in the formation zones. In contrast to
other permeability modification solutions, the current invention
retains its effectiveness even in the presence of hydrocarbons.
[0014] I. Well Treatment Solutions
[0015] One embodiment of the current invention provides a
permeability modifying aqueous well treatment solution comprising a
hydrophilic reactive polymer, a hydrophobic compound selected for
its ability to react with the hydrophilic reactive polymer and a
surfactant selected for its ability to promote the dissolution of
the hydrophobic compound in the aqueous solution. Optionally, the
aqueous solution may be gelled by the addition of a hydrated
galactomannan gelling agent. Whether or not the aqueous solution is
gelled, the solution will contain a sufficient quantity of pH
adjusting agent to maintain the pH at about 8 or greater. Preferred
pH adjusting agents include buffers, alkali metal hydroxides,
alkali metal carbonates, alkali metal phosphates and other similar
compounds known to those skilled in the art.
[0016] The water utilized to form the aqueous solutions of this
invention can be fresh water, salt water, sea water, brine or any
other aqueous liquid which does not adversely react with other
components of the treating fluid. The water used in well treating
fluids normally contains one or more salts for inhibiting the
swelling of clays in the subterranean formations or zones being
treated or to weight the treating fluid. The most common clay
inhibiting salt utilized is potassium chloride, but other salts can
also be used.
[0017] The galactomannan gelling agents suitable for use in
accordance with the present invention are the naturally occurring
gums and their derivatives such as guar, locust bean, tara, honey
locust, tamarind, karaya, tragacanth, carrageenan and the like.
These gums are generally characterized as containing a linear
backbone having various amounts of galactose units attached
thereto. The gums can also be characterized as having one or more
functional groups such as cis-hydroxyl, hydroxyl, carboxyl,
sulfate, sulfonate, amino or amide. Preferred galactomannan gelling
agents suitable for use in the current invention include, one or
more gelling agents selected from the group of guar,
hydroxyethylguar, hydroxypropylguar, carboxymethylguar,
carboxymethylhydroxyethylguar and carboxymethylhydroxypropylguar.
Of these, guar is the most preferred.
[0018] When it is desired to gel the aqueous solution, one or more
of the above mentioned glactomannan gelling agents are dissolved in
water, the gelling agents are hydrated and a viscous aqueous gel is
formed. When used, the galactomannan gelling agent or agents are
dissolved in the aqueous solution in an amount in the range of from
about 0.06% to about 0.72% by weight, more preferably in an amount
in the range of from about 0.12% to about 0.36%, most preferably
about 0.30%.
[0019] Due to the relative insolubility of hydrophobic compounds in
aqueous solutions, the current invention preferably includes a
surfactant selected for its ability to promote the dissolution of
the hydrophobic compound in the aqueous solution. In general, the
surfactants can be anionic, cationic, amphoteric or neutral. Thus,
surfactants suitable for use in the current invention include, but
are not limited to, alkyl ammonium surfactants, betaines, alkyl
ether sulfates, alkyl ether sulfonates, and ethoxylated alcohols.
Particularly preferred surfactants include alkyl ether sulfonates.
Typically, the surfactant will be present within the aqueous
solution in amounts ranging from about 0.1% to about 2.0% by
weight.
[0020] The hydrophilic reactive polymers suitable for use in the
aqueous solutions of the current invention are preferably polymers
containing reactive amino groups in the polymer backbone or as
pendant groups. A more preferable polymer contains dialkyl amino
pendant groups. Most preferably the polymer contains a dimethyl
amino pendant group and contains at least one monomer selected from
dimethylaminoethyl methacrylate or dimethylaminopropyl
methacrylamide. Suitable polymers include homo-, co- or terpolymers
such as but not limited to polyethyleneimine, polyvinylamine,
poly(vinylamine/vinyl alcohol), chitosan, polylysine and alkyl
acrylate polymers in general. Non-limiting examples of specific
alkyl acrylate polymers include polydimethylaminoethyl
methacrylate, polydimethylaminopropyl methacrylamide,
poly(acrylamide/dimethylaminoethyl methacrylate),
poly(acrylamide/dimethylaminopropyl methacrylamide), poly(acrylic
acid/dimethylaminoethyl methacrylate). The most preferred polymers
are polydimethylaminoethyl methacrylate and polydimethylaminopropyl
methacrylamide. As noted above, the in situ reaction of the
hydrophilic polymer with a hydrophobic compound will generate a
relative permeability modifier.
[0021] The preferred hydrophobic compounds suitable for use in the
aqueous solutions of the current invention include but are not
necessarily limited to alkyl halides. Preferably, the alkyl chain
portion of the hydrophobic compound has from about 6 to about 30
carbons. A particularly preferred hydrophobic compound is cetyl
bromide.
[0022] In general, the hydrophilic reactive polymer will comprise
from about 0.1 to about 2.0 percent by weight of the aqueous
solution and the hydrophobic compound will comprise from about 0.01
to about 1.0 percent by weight of the aqueous solution. Preferably,
the hydrophilic reactive polymer will comprise from about 0.2 to
about 1.5 percent by weight and the hydrophobic compound will
comprise from about 0.02 to about 0.5 percent by weight.
[0023] The reaction of the hydrophilic reactive polymer and
hydrophobic compound yields a hydrophobically modified polymer,
i.e. a hydrophobically modified, water soluble, relative
permeability modifier (RPM). Typically the resulting polymers have
molecular weights in the range of about 250,000 to about 3,000,000.
The charged portion of the resulting compound promotes attachment
of the compound to the porosities of the subterranean formation. As
a result, the permeability of the treated portion of the formation
to water is reduced or eliminated while the permeability of the
formation to hydrocarbons is substantially unchanged.
[0024] Thus, a preferred aqueous solution for reducing the water
permeability of a subterranean formation comprises a hydrophilic
reactive polymer such as poly-dimethylaminoethylmethacrylate, a
hydrophobic compound such as cetyl bromide and a surfactant
selected to promote the dissolution of the cetyl bromide in the
aqueous solution. The concentration of
poly-dimethylaminoethylmethacrylate in the solution may range from
about 0.1 to about 2.0 percent by weight. Preferably, the
poly-dimethylaminoethylmethacrylate comprises about 0.2% by weight.
The concentration of cetyl bromide may range from about 0.01 to
about 1.0 percent by weight. The preferred concentration of cetyl
bromide is about 0.1% by weight. The preferred surfactant for use
with cetyl bromide is an alkyl ether sulfonate and the
concentration of the alkyl ether sulfonate may range from about
0.01 to about 1.0 percent by weight. As noted above, the solution
may optionally contain a hydrated galactomannan gelling agent in an
amount ranging from about 0.06% to about 0.72% by weight.
Additionally, the solution may optionally contain any suitable
proppant known to those skilled in the art.
[0025] In an alternative embodiment, the current invention provides
an aqueous well treatment fluid comprising a pre-reacted
hydrophobically modified, water soluble relative permeability
modifier (pre-reacted hydrophobically modified RPM). In this
embodiment, the pre-reacted hydrophobically modified RPM is
preferably the reaction product of a hydrophilic reactive polymer
and a hydrophobic compound. Hydrophilic reactive polymers suitable
for use in the aqueous solutions of the current invention are
preferably polymers containing reactive amino groups in the polymer
backbone or as pendant groups. A more preferable polymer contains
dialkyl amino pendant groups. Most preferably the polymer contains
a dimethyl amino pendant group and contains at least one monomer
selected from dimethylaminoethyl methacrylate or
dimethylaminopropyl methacrylamide. Suitable polymers include
homo-, co- or terpolymers. Examples of such polymers include but
are not limited to polyethyleneimine, polyvinylamine,
poly(vinylamine/vinyl alcohol), chitosan, polylysine and alkyl
acrylate polymers in general. Additional examples of alkyl acrylate
polymers include polydimethylaminoethyl methacrylate,
polydimethylaminopropyl methacrylamide,
poly(acrylamide/dimethylaminoethyl methacrylate),
poly(acrylamide/dimethy- laminopropyl methacrylamide), poly
(acrylic acid/dimethylaminoethyl methacrylate). The most preferred
polymers are polydimethylaminoethyl methacrylate and
polydimethylaminopropyl methacrylamide.
[0026] Additional polymers useful in this embodiment of the current
invention are preferably prepared from a variety of hydrophilic
monomers and hydrophobically modified hydrophilic monomers.
Examples of particularly suitable hydrophilic monomers which can be
utilized include, but are not limited to, acrylamide,
2-acrylamido-2-methyl propane sulfonic acid,
N,N-dimethylacrylamide, vinyl pyrrolidone, dimethylaminoethyl
methacrylate, acrylic acid, dimethylaminopropylmethacr- ylamide,
vinyl amine, vinyl acetate, trimethylammoniumethyl methacrylate
chloride, methacrylamide and hydroxyethyl acrylate. Of these,
acrylamide, 2-acrylamido-2-methyl propane sulfonic acid, acrylic
acid, dimethylaminoethyl methacrylate, dimethylaminopropyl
methacrylamide and vinyl pyrrolidone are preferred.
[0027] A variety of hydrophobically modified hydrophilic monomers
can also be utilized to form the polymers useful in accordance with
this invention. Particularly suitable hydrophobically modified
hydrophilic monomers include, but are not limited to, alkyl
acrylates, alkyl methacrylates, alkyl acrylamides and alkyl
methacrylamides wherein the alkyl radicals have from about 4 to
about 22 carbon atoms, alkyl dimethylammoniumethyl methacrylate
bromide, alkyl dimethylammoniumethyl methacrylate chloride and
alkyl dimethylammoniumethyl methacrylate iodide wherein the alkyl
radicals have from about 4 to about 22 carbon atoms and alkyl
dimethylammoniumpropyl methacrylamide bromide, alkyl
dimethylammonium propylmethacrylamide chloride and alkyl
dimethylammoniumpropyl methacrylamide iodide wherein the alkyl
groups have from about 4 to about 22 carbon atoms. Of these,
octadecyldimethylammoniumethyl methacrylate bromide, hex
adecyldimethylammoniumethyl methacrylate bromide,
hexadecyldimethylammoni- umpropyl methacrylamide bromide,
2-ethylhexyl methacrylate and hexadecyl methacrylamide are
preferred.
[0028] Polymers that are useful in accordance with the present
invention can be prepared by polymerizing any one or more of the
hydrophilic monomers with any one or more of the hydrophobically
modified hydrophilic monomers. Methods for preparing such polymers
are known to those skilled in the art as represented by U.S. Pat.
No. 6,476,169 incorporated herein by reference.
[0029] Accordingly, suitable polymers have estimated molecular
weights in the range of from about 250,000 to about 3,000,000 and
have mole ratios of the hydrophilic monomer(s) to the
hydrophobically modified hydrophilic monomer(s) in the range of
from about 99.98:0.02 to about 90:10. Particularly suitable
polymers having molecular weights and mole ratios in the ranges set
forth above include, but are not limited to,
acrylamide/octadecyldimethylammoniumethyl methacrylate bromide
copolymer, dimethylaminoethyl
methacrylate/hexadecyldimethylammoniumethyl methacrylate bromide
copolymer, dimethylaminoethyl methacrylate/vinyl
pyrrolidone/hexadecyldimethylammoniumethyl methacrylate bromide
terpolymer and acrylamide/2-acrylamido-2-methyl propane sulfonic
acid/2-ethylhexyl methacrylate terpolymer. Of these, a
dimethylaminoethyl methacrylate/hexadecyldimethylammoniumethyl
methacrylate bromide copolymer having a mole ratio of hydrophilic
monomer to hydrophobically modified hydrophilic monomer of 95:5 is
a preferred pre-reacted hydrophobically modified RPM.
[0030] Following preparation of the hydrophobically modified RPM,
the hydrophobically modified RPM is added to water in a sufficient
quantity to yield a solution having from about 0.05% to about 1.0%
by weight. Water suitable for use in this embodiment of the current
invention is defined above. Likewise this embodiment of the current
invention may also contain salts suitable for inhibiting the
swelling of clays. Additionally, the galactomannan gelling agents
described above may be used in amounts ranging from about 0.06% to
about 0.72% by weight. Preferably, the concentration of the
galactomannan gelling agent will be in the range of about 0.12% to
about 0.36% by weight with the most preferred concentration being
about 0.30% by weight. Further, the solution may optionally contain
any suitable proppant known to those skilled in the art.
[0031] Unlike the well treatment solution wherein the
hydrophobically modified RPM is prepared in situ, this embodiment
of the current invention does not require a surfactant in the well
treatment solution, as the hydrophobically modified RPM already
exists prior to injection downhole. Further, the solution will not
require a pH adjusting agent capable of maintaining the pH at about
8 or greater. Thus, the well treatment solution comprising the
pre-reacted hydrophobically modified RPM can be adjusted to a pH
more suited to the environment of the formation. Typically, the pH
of the well treatment solution comprising the pre-reacted
hydrophobically modified RPM will be between about 4 and about
8.
[0032] As known to those skilled in the art, the aqueous solutions
of the current invention may also contain other well treatment
compounds such as but not necessarily limited to scale inhibitors,
clay stabilizers, and corrosion inhibitors.
[0033] II. Treating a Hydrocarbon Formation with Hydrophobically
Modified RPM
[0034] The current invention also provides methods for stimulating
or re-stimulating hydrocarbon producing formations. The methods of
the current invention preclude or at least reduce the production of
water from a hydrocarbon formation. The methods of the current
invention comprise the injection of the aqueous well treatment
solutions described above through the wellbore, into the
hydrocarbon producing formation. Preferably, the aqueous well
treatment solution is injected ahead of a fracture stimulation
fluid. The injection rate of the aqueous well treatment solution is
substantially equivalent to the injection rate of the fracture
stimulation fluid. Once in the formation, the hydrophobically
modified RPM bonds itself to the matrix.
[0035] In one embodiment, the method of the current invention
injects an aqueous well treatment solution comprising a hydrophilic
reactive polymer and a hydrophobic compound into the formation.
According to this method, the well treatment solution is placed in
the formation and the hydrophilic reactive polymer and the
hydrophobic compound are allowed to react in situ. The in situ
reaction generally is effected at a formation temperature in excess
of 23.degree. C. (75.degree. F.) and preferably in excess of about
37.degree. C. (100.degree. F.). To facilitate the rapid formation
of the hydrophobically modified RPM, the pH of the well treatment
solution is adjusted to about 8 or higher by the addition of an
alkaline agent such as caustic or the like. Preferably the pH is
adjusted to a level above about 9.5 and most preferably about
11-12.
[0036] In another preferred embodiment, the current invention
injects a well treatment solution comprising a hydrophobically
modified RPM. According to this method, the pH of the well
treatment solution can be adjusted to a level lower than 8.0, if
appropriate for the particular formation.
[0037] Either method may be used to stimulate the production of
hydrocarbons from subterranean formations. When initially
stimulating a formation, the injection of either aqueous well
treatment solution is normally followed by a crosslinked gelled
treatment fluid to extend fractures into the subterranean formation
from the wellbore. In one embodiment, the crosslinked gelled
treatment fluid also displaces or drives the aqueous well treatment
solution into the resulting fractures.
[0038] The method of the current invention utilizing a solution
comprising the hydrophilic reactive polymer and hydrophobic
compound will be described first. In this method, the well
treatment solution is pumped into the formation at rates sufficient
to create a fracture and the solution is allowed to leak off into
the matrix of the formation. This solution is normally followed by
a crosslinked, proppant laden fluid. Following fracturing
operations, a shut-in period of time may be necessary to permit the
in situ reaction of the compounds. The requirement of a shut-in
period will be determined based on downhole temperature and
measured depth of the wellbore. The subsequent in situ reaction
generates the hydrophobically modified RPM within the wellbore or
the matrix of the formation. The resulting hydrophobically modified
RPM bonds to the matrix of the formation thereby at least reducing
the formation permeability to water.
[0039] When the aqueous well treatment solution comprises a
hydrophilic reactive polymer and a hydrophobic compound, the
solution may additionally include a quantity of a clay control
additive such as potassium chloride or tetramethylammonium chloride
or the like. Additionally, the solution preferably contains a pH
adjusting agent such as caustic or the like to raise the pH to a
level of about 8 or higher and most preferably to a range of about
11 to about 12. Adjustment of the pH of the solution to the
indicated range will enhance the reaction rate of the hydrophilic
reactive polymer and the alkyl halide. Additionally, a surfactant
is commonly added to promote dissolution of the hydrophobic
compound in the aqueous well treatment solution.
[0040] As noted above, the current invention also provides for
displacement of the aqueous solution into the formation when
pressure is exerted on the solution by a gelled fluid or a
crosslinked gelled fluid subsequently pumped downhole. The water
and gelling agents of the crosslinked gelled fluid used to
fracture, i.e. stimulate, the formation may be any of those
previously described or known to those skilled in the art.
Preferably the crosslinking agent comprises a borate composition.
The borate composition acts as a buffering agent for the treating
fluid and as crosslinking promoter for the hydrated galactomannan
gelling agent in the treating fluid. Preferably the borate
crosslinking composition is a liquid solution generally comprised
of water, a soluble boron source such as boric acid and an
alkanolamine or alkylamine. The water utilized in forming the
borate composition is preferably fresh water, but other aqueous
liquids can be utilized so long as they do not adversely react with
or otherwise affect other components of the borate composition or
the treating fluid formed therewith. The water can include one or
more freezing point depressants such as ethylene glycol, propylene
glycol, alcohols or the like to prevent the borate composition from
freezing in cold weather. Preferably, ethylene glycol is combined
with the water used in an amount of 50% by weight of the resulting
solution. This concentration of ethylene glycol depresses the
freezing point of the borate composition to less than about
-28.degree. C. (-20.degree. F.). The term "water" when used herein
relating to the borate composition means water or other suitable
aqueous liquid with or without one or more freezing point
depressants dissolved therein. The water is preferably present in
the borate composition in an amount in the range of from about 96%
to about 5% by weight of the composition, most preferably about
60%.
[0041] The boron source can comprise substantially any boron
containing compound capable of yielding borate in a solution
maintained at a pH above about 7. The boron source can be provided
by, for example, boric acid, boric oxide, pyroboric acid, metaboric
acid, borax, sodium tetraborate and the like. For simplicity,
reference will hereinafter be made to borate or boron content as
boric acid or boric acid equivalents. That is, if a weight
percentage is specified for boron content as boric acid, it is to
be understood that a chemical equivalent amount of, for example,
borax or sodium tetraborate could be substituted for the boric
acid.
[0042] The boron source is preferably present in the crosslinking
composition in an amount as boric acid in the range of from about
3% to about 82% by weight of the composition, most preferably in an
amount of about 30%.
[0043] A variety of alkanolamines or alkylamines can be utilized in
the borate crosslinking composition, but the quantity of boron in
the composition is reduced as the molecular weight of the amine
included in the composition increases. Thus, it is preferred that a
relatively low molecular weight alkanolamine be used such as an
ethanolamine. The most preferred low molecular weight alkanolamine
is mono-ethanolamine. The use of a low molecular weight
alkanolamine in the borate composition produces the further benefit
of making the composition cold weather stable, i.e., the
composition without a freezing point depressant therein does not
crystallize or the like at low temperatures down to about
-15.degree. C. (5.degree. F.). Other suitable alkanolamines include
diethanolamine, 1-amino-2-propanol, 1-amino-2-butanol and the like.
The alkylamines can comprise an aliphatic polyamine such as, for
example, ethylenediamine, diethylenetriamine,
triethylenetetraamine, 1,2-diaminopropane, tetraethylenepentamine
and the like. The alkanolamine or alkylamine is generally present
in the crosslinking and buffering composition in an amount in the
range of from about 1% to about 13% by weight of the composition.
When mono-ethanolamine is utilized, it is preferably present in the
composition in an amount of about 10% by weight of the
composition.
[0044] A particularly preferred highly concentrated, stable
crosslinking composition useful in accordance with this invention
is comprised of water present in an amount of about 60% by weight
of the composition, boron calculated as boric acid present in an
amount of about 30% by weight of the composition and
mono-ethanolamine present in an amount of about 10% by weight of
the composition. This composition is stable and is easily pumped
and metered at low temperatures. The borate ion concentration in
the composition is very high, and the composition has the ability
to buffer the resulting treating fluid to a pH between about 8.4
and 9 without the need for any other chemicals such as caustic,
sodium carbonate or other buffer.
[0045] The crosslinking composition comprised of water, a boron
source and alkanolamine or alkylamine is present in the borate
crosslinked gelled aqueous well treating fluids of this invention
in an amount in the range of from about 0.05% to about 0.8% by
weight of water in the treating fluids, preferably in an amount in
the range of from about 0.15% to about 0.4%.
[0046] A particularly preferred borate crosslinked gelled aqueous
well treating fluid of this invention is comprised of water,
hydrated guar present in an amount of about 0.30% by weight of the
water and the preferred borate composition for buffering the
treating fluid and crosslinking the hydrated guar comprised of
water, boric acid and mono-ethanolamine described above present in
the treating fluid in an amount of about 0.2% by weight of the
water.
[0047] As will be understood by those skilled in the art, a variety
of conventional additives can be included in the well treating
fluids of this invention such as gel stabilizers, gel breakers,
clay stabilizers, bactericides, fluid loss additives, proppants,
such as sand, and the like which do not adversely react with the
treating fluids or prevent their use in a desired manner.
[0048] Thus, in one embodiment the improved method of the present
invention for treating a subterranean formation penetrated by a
wellbore comprises the steps of preparing an aqueous treating fluid
(which optionally can be gelled) comprising a hydrophilic reactive
polymer and a hydrophobic compound and preparing a proppant laden,
crosslinked, gelled aqueous treatment fluid. The prepared fluids
are pumped into the subterranean formation at rates and pressures
sufficient to fracture the formation. Optionally, the aqueous
treating fluid may contain a proppant.
[0049] Depending on wellbore and formation conditions, a shut-in
period of one minute to several hours may be required to permit the
in situ reaction of the hydrophilic reactive polymer and the
hydrophobic compound. Typically, the length of the borehole and the
downhole X temperature will determine the length of any shut-in
period. For example, a deep borehole with temperatures in the range
of about 93.degree. C. (200.degree. F.) or greater may not require
a shut-in period. In general, shallow, cooler formations will
require longer shut-in periods possibly extending up to 24 hours.
Those skilled in the art will be able to readily determine the
necessity for and the time period of any shut-in periods. During
the shut-in period or the transport time downhole, the hydrophilic
reactive polymer and the hydrophobic compound react forming the
hydrophobically modified RPM capable of adhering to the formation
matrix. The resulting polymer, i.e. the hydrophobically modified
RPM, inhibits water transport through the formation without
substantially interfering with hydrocarbon production.
[0050] In such treatments, the gelled well treating fluids are
pumped through the wellbore into the subterranean zone or formation
to be fractured at a high rate and pressure whereby fractures are
formed in the subterranean zone or formation and a propping agent,
such as sand is suspended in the crosslinked treating fluid and
carried into the fractures and deposited therein. Thereafter, the
gelled and crosslinked carrier fluids are caused to break, i.e.,
revert to a thin fluid capable of flowing out of the fractures
while leaving the proppant therein. Preferably, the time necessary
to break the gel is less than or equal to the time of any necessary
shut-in period. Production of hydrocarbons then may be initiated
from the fracture stimulated treated subterranean formations.
[0051] In another embodiment, the method for treating a
subterranean formation penetrated by a wellbore comprises the steps
of preparing an aqueous treating fluid (which optionally can be
gelled) comprising a pre-reacted hydrophobically modified RPM and
preparing a proppant laden, crosslinked, gelled aqueous treatment
fluid. Optionally, the aqueous treating fluid may contain a
proppant. The prepared fluids are pumped into the subterranean
formation at rates and pressures sufficient to fracture the
formation. The hydrophobically modified RPM adheres to the matrix
and thereby inhibits water transport through the formation without
substantially interfering with hydrocarbon production. Preferably,
the concentration of the pre-reacted hydrophobically modified RPM
in the aqueous treating fluid ranges from about 0.05% to about 1.0%
by weight.
[0052] In such treatments, the gelled well treating fluids are
pumped through the wellbore into the subterranean zone or formation
to be fractured at a sufficient rate and pressure to fracture the
subterranean zone or formation. During the fracturing process a
propping agent, such as sand, suspended in the crosslinked treating
fluid is carried into the fractures and deposited therein.
Thereafter, the gelled and crosslinked carrier fluids are caused to
break, i.e., revert to a thin fluid capable of flowing out of the
fractures while leaving the proppant therein. Production of
hydrocarbons then may be initiated from the fracture stimulated
treated subterranean formations.
[0053] In contrast to the method described above wherein a
hydrophilic reactive polymer reacts in situ with a hydrophilic
compound, the embodiment utilizing the pre-reacted hydrophobically
modified RPM does not require the addition of a surfactant. Further
addition of a pH adjusting agent is not necessary. Additionally,
this embodiment of the current invention does not require shutting
in the well for a period of time to permit the in situ generation
of the hydrophobically modified RPM. In all other aspects, the
embodiment of the current invention utilizing the pre-reacted
hydrophobically modified RPM may be practiced in the same manner as
described above relating to the in situ reaction of a hydrophilic
reactive polymer and a hydrophobic compound.
[0054] The current invention additionally provides methods for
re-stimulating producing formations. As is known to those skilled
in the art, the percentage of water produced with hydrocarbons
frequently increases over the life of a subterranean formation.
Additionally, certain wells provide the opportunity for extending
the reach of the existing propped fracture. The presence of
hydrocarbons in the water producing zones frequently precludes the
use of known permeability modifying compounds. However, the
compositions and methods of the current invention have been shown
to effectively reduce formation permeability to water without
negatively impacting hydrocarbon production.
[0055] In general, the methods for re-stimulating production are
practiced as described above, except in this instance a propped
fracture is already in existence. Accordingly, the re-stimulation
process requires pumping the aqueous well treatment solution of
hydrophilic reactive polymer and hydrophobic compound or the
solution containing the pre-reacted hydrophobically modified RPM at
sufficient pressure and rate to re-open and preferably extend the
fracture. Preferably, the aqueous well treatment solution is
followed with a crosslinked proppant laden fluid to help hold the
fracture open once the pressure is relieved. Alternatively, the
solutions of the current invention may contain a proppant.
[0056] Thus, the aqueous well treatment solutions described above
are suitable for fracture stimulation or re-stimulation of a
hydrocarbon producing formation. In the case of a re-stimulation,
the existing fracture face and the newly created fracture face will
be treated by the resulting relative permeability modifier
generated in situ by the aqueous solution of the current invention
or by the pre-reacted hydrophobically modified RPM. Thus, the
re-stimulation process will simultaneously improve production of
hydrocarbons while reducing or eliminating the production of water
from the treated portion of the formation.
[0057] In order to further illustrate the compositions and methods
of the present invention, the following examples are provided.
EXAMPLE 1
[0058] A multi-pressure tap Hassler sleeve containing a Berea
sandstone core was utilized to determine the water permeability
reduction produced by the in-situ reaction of
polydimethylaminoethyl methacrylate with cetyl bromide. The
permeability reduction tests were run at a temperature of
200.degree. F. utilizing a brine containing 9% by weight sodium
chloride and 1% by weight calcium chloride.
[0059] The following procedure was utilized for a first series of
tests, the results of which are provided below in Table I. The
above described brine was flowed through the Berea core, followed
by oil (kerosene), followed by brine. This third brine flow was
maintained until the pressure stabilized, yielding an initial brine
permeability. A treatment solution, consisting of 100 mL of a
solution of polydimethylaminoethyl methacrylate, cetyl bromide and
cetyltrimethylammonium bromide dissolved in 2% KCl brine at pH 12,
was flowed into the core. The core was then shut-in for
approximately 24 hours to allow reaction of the polymer and cetyl
bromide. Following this shut-in period, brine flow was
re-established until the pressure stabilized, yielding a final
permeability. The percent brine permeability reduction was
calculated using the formula [1-(final permeability/initial
permeability)].times.100- . The multi-pressure tap Hassler sleeve
allowed the core permeability to be divided into four segments. In
the tests, the initial brine flow was from segment 1 to segment 4.
The treatment solution flow was from segment 4 to segment 1, and
the final brine flow was from segment 1 to segment 4. The initial
and final permeabilities were calculated for the middle two
segments, i.e., segments 2 and 3. In addition, the overall, or
total core permeability is also calculated. The results of the
tests are set forth in Table I below. The results of the in-situ
reaction treatment as provided in Table I clearly demonstrate the
ability of the current invention to reduce the brine permeability
of a formation.
1TABLE I Total Cetyl Brine Segment 2 Segment 3 trimethyl Perme-
Brine Brine ammo- ability Perme- Perme- Test Cetyl nium Re- ability
ability # Polymer Bromide bromide duction Reduction Reduction 1
0.7% 0.08% 0.05% 50% 32% 32% 2 1.1% 0.1% 0.07% 70% 61% 74%
EXAMPLE 2
[0060] The tests described in Table I were repeated using different
flow sequences and a "parallel" core setup. In the parallel setup,
two Berea cores were connected during the treatment phase such that
the treatment has equal opportunity to flow into either core. In
this test, the flow sequence for the first core, designated the
"water" core, was simply brine-treatment-brine. In the second core,
designated the "oil" core, the flow sequence was
brine-oil-brine-oil-treatment-oil. The flow sequences on these two
cores prior to the treatment phase were carried out separately,
that is, during this step the cores were not connected. This step
determined the initial brine and oil permeabilities. The cores were
connected for the treatment phase, then disconnected for the final
brine and oil flow. The results from the final brine and oil flow
were used to determine the final brine and oil permeabilities. The
percent permeability reductions were calculated as discussed in
Example I.
[0061] In this test, the treatment consisted of a preformed
hydrophobically modified polydimethylaminoethyl methacrylate
formulated in a typical fracturing fluid. The fluid contained 0.2%
of the pre-formed hydrophobically modified polydimethylaminoethyl
methacrylate and 0.3% of a guar gelling agent, as well as biocides,
buffers, breakers and other additives well known to those skilled
in the art. A total of 25 mL of this treatment solution was pumped
into the two cores in the parallel setup. Of the total 25 mL of
treatment, 16 mL entered the water core and 9 mL entered the oil
core. This test is intended to exhibit the effect of the polymer on
water producing and oil producing zones when placed in a fracturing
fluid. The results of the tests are set forth in Table II below.
From Table II, it can be seen that the treatment did result in
significant permeability reduction to the water core, with very
little permeability reduction to the oil core.
2TABLE II Segment 2 Segment 3 Total Permeability Permeability
Permeability Core Reduction Reduction Reduction Water 59% 22% 55%
Oil 0 0 22%
[0062] The foregoing test results demonstrate the ability of the
reactive polymers to selectively reduce core permeability to water
flow while not preventing oil flow through the various core
samples.
[0063] Other embodiments of the current invention will be apparent
to those skilled in the art from a consideration of this
specification or practice of the invention disclosed herein.
However, the foregoing specification is considered merely exemplary
of the current invention with the true scope and spirit of the
invention being indicated by the following claims.
* * * * *